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OE Press: 2016 / August (78)

Global Maritime Consultancy & Engineering successfully led the disconnection and towing operations of the Njord A semisubmersible floating production platform from the Njord field. The Njord A platform arrived safely in Klosterfjorden on the 23 August, where a handover to Kværner was achieved.

Njord A disconnection and tow to shore. Image from Global Maritime.

The 346nm journey was carried out by Global Maritime, on behalf of the operator Statoil. The news follows the successful towing of the oil storage and offloading vessel Njord B by Global Maritime to Sterkoder, Kristiansund earlier this summer.

Global Maritime was responsible for the project management, engineering, design, fabrication and procurement of equipment, as well as all offshore management activities for the Njord A and Njord B mooring disconnection and tow.

Global Maritime’s responsibilities included the disconnection of 12 mooring lines, the recovery of one complete mooring line (excluding the suction anchor) for onshore inspection and the towing-in of the Njord A platform to Klosterfjorden outside the Stord yard. Statoil coordinated the decommissioning activities including the disconnection of risers and the temporary plugging of wells.

“With a project of such complexity and with the subsea infrastructure still in tact, it was crucial that mooring disconnection activities and the towing of the platform took place with maximum precision and care. This is what Global Maritime achieved with the platform being disconnected from its moorings, departing the field, and arriving in Stord ahead of schedule. We look forward to working with Statoil on future similar projects,” David Sutton, CEO of Global Maritime Consultancy & Engineering said.

Last week, Njord A was towed to the Kværner Stord yard in Norway for reinforcement and renovation works, which will enable it to return to production up to and beyond 2030.

Irish explorer Providence Resources has appointed a well management services contractor for its deepwater Druid well in the Porcupine Basin.

The firm also expects to save 30% on drilling costs, thanks to a drop in rates in the last estimate.

Drilling on the Paleocene Druid prospect is expected in June 2017. Druid is in Frontier Exploration Licence 2/14, in 2250m water depth in the southern Porcupine Basin, 220km off the south west coast of Ireland.

FEL 2/14 also cntains the Drombeg prospect.

Providence and its partner Sosina have appointed Senergy Wells Limited (Senergy), a wholly owned subsidiary of Lloyds Register, to provide integrated well management services for the drilling program. Under the terms of the contract, Senergy will provide management and well engineering services for the design and construction of the Druid well under the LR Global Management System - Well Project Delivery Process.

Based on updated market rates, the latest gross well cost for Druid is estimated at about US$35 million, which compares to $46 million, previously estimated.

Norway's Det norske oljeselskap has made a 24-74 MMboe oil discovery on exploration well 25/2-18 S on the Langfjellet prospect in license 442 the Norwegian North Sea.

The well encountered a gross oil column of 109m in the Vestland Group, says Det norske. A technical sidetrack was drilled to collect data and the well is currently being prepared for a sidetrack and welltest.

Preliminary volume estimates for the discovery are 24-74 MMboe. The licensees will evaluate the discovery with regards to a potential development together with other discoveries in the area. Following the successful drilling results at Langfjellet, the licensees have identified further prospectivity within the license.

Det norske is operator and holds a 90% working interest in PL442. LOTOS Exploration and Production Norge holds the remaining 10%.

GE says it is the world’s first subsea gas compression system with a full subsea power supply, transmission and distribution system. GE had already revealed to OE that it has qualified a subsea power distribution system - read our August issue or here to find out more.

The Ormen Lange Pilot was a first of its kind and was designed to test a full scale integrated subsea compression system in submerged conditions with real hydrocarbons.

It has been run by Norske Shell and its license partners Petoro, Statoil, Dong and ExxonMobil since 2011 at Shell’s test facility at Nyhamna in Norway where the gas from the Ormen Lange field reaches shore.

While Shell decided to halt plans for subsea compression at Ormen Lange in 2014, citing costs and reservoir data, the firm has continued assessing options for the field, including a subsea compression project on a 120km stepout, but also subsea separation, a wet gas compression solution, and floating facilities. The firm says it is very much still looking at its options.

Ormen Lange was discovered in 1997 and has been producing since 2007, in 600-1100m water depth in the southern part of the Norwegian Sea, about 130km northwest of Kristiansund.

GE has been a key collaboration partner with Shell in the development of the compression system and supplied a number of the technologies to the project, including GE Oil & Gas’ Blue-CTM compressor – a centrifugal compressor specifically designed for subsea - and the world’s first subsea power supply, transmission and distribution system.

The system enables operators to conduct gas compression on the seabed, reducing the need to introduce additional power generation on nearby offshore facilities.

Sitting at the heart of the compressor is the electrical package provided by GE’s Power Conversion business and due to GE’s expertise in electrical engineering, the high-speed motor and the high power drive provided are capable of operating hundreds of meters below the sea level reliably.

Neil Saunders, President & CEO, Subsea Systems & Drilling, GE Oil & Gas, said: “We are very proud of what we have achieved in partnership with Shell. We leveraged the GE Store, using our domain expertise and heritage across the GE portfolio, including rotating machinery, power electronics, high voltage designs and subsea production systems. Today, we are designing the next generation of compact and modular subsea compression systems to unlock new possibilities for power and processing worldwide”.

The GE technologies that were tested as part of the Ormen Lange Pilot include the 12.5MW Blue-CTM subsea compressor, subsea power supply, transmission and distribution system, subsea switch gear and variable speed drives, subsea uninterruptible power supply (UPS), connectors and electric actuators. The system also had a Naxys acoustic leak detection system.

Ithaca Energy’s FPF-1 floating production facility (FPU) is now on location on the Stella field in the UK North Sea, according to partner Petrofac.

Illustration of the Greater Stella Area, from Ithaca.

Aimed to start-up in November, the FPU competed the onshore commissioning, Petrofac said in its 1H 2016 report.

Following a series of setbacks, the FPF-1 set sail for Stella in early August from the Remontowa yard offshore Poland, after completing final marine system trials.

In Ithaca’s 1H 2016 report, the company confirmed that the FPF-1 will be moored on location using 12 pre-installed anchor chains. The dynamic risers and umbilicals that connect the subsea infrastructure to the vessel will then be installed. Thereafter, commissioning of the various processing and utility systems that can only be undertaken on location with hydrocarbons from the field will be completed.

The unit is due to produce the Greater Stella Area, containing the Stella and Harrier fields, initially via five subsea wells on Stella, with plans to also tie-in the Hurricane discovery and potentially other prospects in the area.

Statoil aims to conduct a major exploration campaign in several parts of the Barents Sea in 2017, in addition to strengthening its position in the area through several transactions with other companies.

Barents map, from Statoil.

“We have worked systematically on developing an exploration portfolio for testing good and independent prospects in 2017 and 2018. For 2017 we see promising prospects in different parts of the Barents Sea. For example, we want to explore the Blåmann prospect in the Goliat area, Koigen Central in PL718 on Stappen High and the Korpfjell prospect in PL859 that was awarded in the 23rd licensing round,” Jez Averty, Statoil’s head of exploration on the Norwegian continental shelf (NCS) said.

In addition to an exploration well in PL849 (Blåmann), awarded in the award in predefined areas (APA) in January 2016, Statoil and the operator Eni have also agreed on drilling a new exploration well in PL229 (Goliat) in 2017. Statoil has already a rig on contract which is suitable for operation in the Barents Sea. The company is working on obtaining approval from partners and authorities for an exploration campaign in 2017 covering between five and seven wells in the Barents Sea.

During the past months Statoil has entered or increased its share in five licenses in the Norwegian part of the Barents Sea by a number of agreements with Point Resources, DEA, OMV and ConocoPhillips.

“Giving us access to new acreage, the transactions demonstrate our belief in continued exploration potential on the NCS. We have played a leading role in the Barents Sea for 40 years, and we are still a guarantee for high activity in the area,” Averty said.

New and major discoveries are crucial to maintain the current NCS production level up to 2030 and beyond. The areas off North Norway will play a key role in reaching this ambition.

“Through these agreements we are strongly increasing our presence in the Hoop area, we are fortifying our position around Johan Castberg, and we see new opportunities in the southwestern part of the Barents Sea,” Averty said.

Statoil completed a comprehensive exploration campaign in the Barents Sea in 2013-2014 without any impact discoveries, but with additional volumes to Johan Castberg through the Drivis discovery. Exploration is a long-term process requiring patience, and information from the previous campaign has been used to further deepen the company’s understanding of the petroleum potential of the Barents Sea.

“We are working actively on replenishing our exploration portfolio through government awards, developing new ideas in existing licenses and making agreements with other companies on acquiring licences. This provides a good basis for exploring more interesting opportunities,” Averty said. “We have also worked efficiently on reducing costs by developing new technology, such as Cap-XTM, and improving drilling efficiency. The wells to be drilled in the south-eastern part of the Barents Sea next year seem to be the most inexpensive offshore exploration wells throughout Statoil.”

Through the Barents Sea Exploration Collaboration (BaSEC) the industry has formed a good basis for carrying out safe and consistent drilling operations. The industry’s joint seismic data gathering in 2014 further demonstrates its will and ability to solve common issues efficiently while taking into account other interests in the same areas.

CGG signed an agreement with GNPC Operating Services Co. (GOSCO), an independent Ghanaian E&P services company, to form a joint-venture company dedicated to conducting high-end 2D, 3D and 4D marine seismic acquisition and related services in the territorial waters of the Republic of Ghana.

The primary aim of the joint-venture company, known as GOSCO Geoscience Ltd. (GGSL), is to make available world-class seismic vessels and state-of-the-art marine seismic acquisition technologies and services to oil and gas industry players operating in Ghana. The new joint venture will be a Ghanaian indigenous company and be based in Accra. Its creation also recognizes and supports the requirement for knowledge transfer and capacity-building in the Ghanaian E&P industry as well as the need for safe and efficient oil and gas operations undertaken to the highest international standards.

Jean-Georges Malcor, CEO, CGG, said: “We have joined forces with GOSCO to set up this joint venture as a response to recent growing industry interest in Ghana’s oil and gas potential. This move is another example of CGG’s strategy to work in partnership with local oil and gas players to benefit from their experience of working in the country while bringing them the benefit of CGG’s global expertise as a leading technology provider. We believe this joint venture will create a strong vehicle for growth in Ghana’s E&P industry.”

According to DNV GL, there is increasing emphasis from regulators on addressing uncertainty in risk assessments to improve safety.

The new approach has been developed in collaboration with the University of Stavanger, Norway, and reflects recent developments in the risk science community. The paper is aligned with the thinking of the PSA in Norway, ISO 31000 and the Society for Risk Analysis.

“The way we conduct risk assessments must be adapted to the needs of decision makers and the challenges they face at any given time. The purpose of the paper is to explain that uncertainty is an instrumental part of risk, and that assessing and communicating the impact of uncertainty can help clients tackle safety-critical decisions with more confidence. It goes beyond what can be quantified in terms of probabilities and exposes risks hidden in assumptions, giving a fuller risk picture,” Marianne Hauso, DNV GL head of section, safety risk management said.

The paper discusses the overall challenge of understanding, interpreting and disseminating risk results. It explores the meaning of uncertainty in relation to risk and how to incorporate uncertainty as a means to assert appropriate actions. The research advocates an iterative, top-down approach to risk assessment, where the focus is placed on the decision-making situation.

“Some uncertainty is incorporated in the probabilities we assign and risk measures we calculate,” Hauso said. “But some uncertainty is hidden in assumptions we make during the risk assessment. This is inevitable – and there is nothing wrong with making assumptions – as long as uncertainties associated with those assumptions are acknowledged and their implications on decisions are understood. Through this approach, together with proper risk communication, uncertainty can be translated into confident decisions and improved safety.”

The approach described in the paper is also the basis of a new upcoming DNV GL recommended practice (RP), ‘Effective update of risk assessments’. This RP will assist operators to maintain an updated risk picture during operations and stop the need for a new, comprehensive risk assessment at regular intervals. The RP will advise on how to identify deviations that matter and to implement appropriate measures to ensure that the risk is under control.

Statoil has gotten a four-month early start at its Gullfaks Rimfaksdalen (GRD) field, which was scheduled for start-up on 24 December. The project has worked faster and now the field is onstream – at lower costs than planned, the company said.

Illustration of GRD, from Statoil.

Recoverable reserves at GRD are approximately 80 MMboe, mostly gas. GRD is in the North Sea, around 5-15km southwest of the Gullfaks A platform at 135m water depth, and 3200m below the seabed. GRD has some 80 MMboe of recoverable resources, mostly gas.

The project delivered is more than US$120 million (NOK 1 billion) below the estimate of the plan for development and operation (PDO), reducing costs from $576 million (NOK 4.8 billion) to around $444 million (NOK 3.7 billion).

The Gullfaks Rimfaksdalen development consists of a standard subsea template with two simple gas production wells, and possibilities for tie-in of two more wells. The well stream is connected to the existing pipeline leading to the Gullfaks A platform.

"Over time we have focused on reducing costs and raising the profitability of our projects to ensure long-term activity and value creation on the Norwegian continental shelf (NCS). Based on a smart concept using standard solutions and existing infrastructure, Gullfaks Rimfaksdalen strongly proves that we are on the right track to succeed on this work," Torger Rød, senior vice president for project development in Statoil said.

“The volumes from Gullfaks Rimfaksdalen help us reach our ambition of maintaining production and a high activity level on the NCS beyond 2030. We have a well-developed infrastructure and we will keep realizing opportunities in the North Sea," Arne Sigve Nylund, executive vice president for development and production Norway said. "This development leads to more production, improved value creation and higher activity level on Gullfaks, and also throughout the value chain related to the field."

Gas and condensate are transported in existing pipelines to the processing plant at Kårstø north of Stavanger for processing, and from there the gas is exported to markets on the European continent.

Gullfaks Rimfaksdalen is one of Statoil’s fast-track projects, aiming to realize resources quickly and inexpensively, for example by using existing infrastructure while it is still available.

Statoil is the operator of GRD with 51% stake. Partners are Petoro (30%) and OMV (19%).

Some US$50 billion has been dropped from the Norwegian oil and gas investment hopper from 2014 up to 2020, according to figures presented at the ONS exhibition and conference in Stavanger today.

The fall, amid a $1 trillion drop in global spending in the same period, is all projects that have been axed entirely, however, said Wood Mackenzie senior analyst Malcolm Dickson.

Speaking at ONS, Dickson said some 10 projects had been deferred or scrapped, while others are being optimized, such as Johan Castberg, helping to reduce planned spending in the 2016-2020 period. Others are currently deemed uneconomic, including Vette and Tommeliten Alpha, says Dickson.

The timing of when these come to FID will be crucial in determining the costs of the kit required for development, says Dickson.

"The best time to FID from that point of view is before 2018, after which we expect demand to pick up in line with oil price recovery. This will push costs up in the global supply chain, and there could be a demand crunch at that point," he says.

"Mid-2017 is the bottom, if you believe in oil price recovery, as we do. That means that cost inflation will begin to creep into fields from 2018 onwards. FID in the next year or so would make sense to capture lower costs," explains Dickson. "However, cost optimization can trump everything. Too many of those projects have breakevens in excess of US$50 a barrel – and simplification, standardization and optimization, not cyclical benefits are the keys to new investment."

For those looking to invest, FIDs targeting 2017 would be optimal for lower costs. Commenting on the effect of the oil price drop on capital investment spend in Norway, Dickson says: "We can’t change the oil price, but we can look to bring costs in line with it. The most prevalent type of optimization has been simplification of projects such as moving to lower cost drilling techniques, scaling down vessel spec and moving from large platforms to subsea."

Examples of optimization include the evidence of more efficient drilling in exploration – with wells being drilled 50% faster than 2013, as well as new technology approaches like Åsgard's subsea compression, which adds around 300 MMboe to that project. Statoil is among the companies benefitting from the use of standardized and simplified well designs to cut time and costs.

"While costs have come down, there’s a lot further to go," says Dickson. Wood Mackenzie's research shows that in 2016, subsea equipment, drilling and seismic will see the most cost deflation.

Based on a recent survey of oil companies and contractors by Wood Mackenzie, independent oil companies are more optimistic of further deflation in 2017 – while the supply chain foresees an earlier demand uptick, curtailing deflation.